UniversityofStavanger SiljeRosnesEgge ACost-EﬃcientApproachtoRiglessP&AofPlatformWells

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Faculty of Science and Technology

MASTER’S THESIS

Study program/Specialization:

Industrial Economics/

Risk analysis, Investment and Finance

Spring semester, 2021

Open Writer:

Silje Rosnes Egge

(Writer’s signature) Faculty supervisor:

Kristin Helen Roll External supervisor(s):

Egil Thorstensen (Aker BP), Martin K. Straume (Aker BP) Thesis title:

A Cost-Efficient Approach to Rigless P&A of Platform Wells

Credits (ECTS): 30 Key words:

Rigless P&A Well intervention Aker BP

Case study

Monte Carlo simulation Cost

Duration iQx P1

Pages: 69

+ enclosure: 6

Stavanger, 11.06.2021

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A Cost-Efficient Approach to Rigless P&A of Platform Wells

Silje Rosnes Egge

University of Stavanger

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Acknowledgements

First of all, I would like to thank my supervisors in Aker BP, Egil Thorstensen and Martin Straume for their invaluable guidance and belief in me throughout this thesis. I am extremely grateful to be involved in your work, and for your enthusiasm for sharing your knowledge, experience, and network. Thanks for supporting me, and for all our valuable discussions.

Further, I wish to express my gratitude to the members of the MINV-team at Aker BP.

Your kindness, help and expertise has been highly appreciated. I hope we meet again.

Thank you to Chris Wetton at Claxton Engineering for taking the time to show me your technology, providing me with helpful information and for answering my questions.

Lastly, I would like to give a special thanks to my supervisor at the University of Stavanger, Kristin Helen Roll, for your continuous feedback, assistance, and encouragement. I sincerely appreciate your availability and close cooperation.

Silje Rosnes Egge University of Stavanger

Stavanger, June 2021

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Abstract

The number of wells to be abandoned on the Norwegian Continental Shelf will increase in the forthcoming years. As a consequence, significant expenditures will be required paid by the individual companies, the state and the society. Despite many technological advances in the oil and gas industry the recent years, traditional P&A of platform wells is still particularly performed by using expensive drilling rigs. In an industry characterized by time-consuming, costly, and complex operations, it is especially interesting to investigate the technological potential of P&A and possible cost-savings this may entail. This thesis therefore considers rigless P&A of platform wells, where the use of well intervention equipment is presented as an alternative approach to traditional rig-based P&A.

Three different case studies of P&A are explored and presented: a rig-based approach, a rigless approach, as well as a combination of rig-based and rigless approach. Well intervention equipment such as wireline and a hydraulic jacking unit are involved in the emerging, rigless method. In order to suggest the most appropriate and cost-efficient abandonment approach, three models are built and used in a Monte Carlo simulation to forecast cost and duration of the different P&A operations. By using well intervention equipment, risk and uncertainties related to unpredictability in the rig marked is removed, which simplifies the time and cost forecasting. To achieve accurate estimation of cost and duration, data is collected with awareness. Historical data, particularly from Aker BP, as well as expert opinions and knowledge, are thus used as simulation input to produce realistic forecasts. The simulation output of the different models is compared, discussed and evaluated using the percentile output values. Findings from the case studies identifies that rigless P&A is much more time-consuming than rig-based P&A. However, partly reducing and completely removing the rig scope leads to significant cost-savings. Since the chosen simulation models consider P&A of a single well, this opens an opportunity for further research within time and cost simulation for multiple wells on platforms.

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Contents iii

List of Figures

1.1 Approximate number of subsea and platform wells requiring future P&A. 2

2.1 Example of a well construction. . . 6

2.2 Wellhead housings associated with the various casing strings. . . 7

2.3 WBS with completed phase 0 and 1. . . 9

2.4 WBS with completed phase 2. . . 10

2.5 WBS with completed phase 3. . . 11

2.6 Illustration of two different approaches for barrier establishment. . . 14

3.1 Graphs showing price elasticity of supply and demand for oil and gas. . 19

3.2 Improvement progress and performance of batch P&Aed wells at Valhall DP. 20 4.1 Illustration of wireline rig up. . . 24

4.2 Illustration of WellRaizer rig up. . . 27

4.3 Drilled and pinned multi-string casing. . . 28

4.4 Bandsaw cutting operation. . . 28

4.5 Splitted pneumatic spiders and prepared for the landing string. . . 30

4.6 Landing string running through the recovery tower. . . 30

4.7 Landing string interface with the wellhead. . . 30

4.8 Elevation principle of the jacking cylinders. . . 31

4.9 DDU operation. . . 31

4.10 Bandsaw operation. . . 31

4.11 Cut casing and drilled 4" hole. . . 31

4.12 Suggested tubing recovery rig up. . . 33

4.13 Suggested casing recovery rig up. . . 35

5.1 Example of a CDF and PDF distribution curve. . . 38

7.1 Time Cumulative Distribution Function for case A. . . 49

7.2 Time Probability Density Function for case A. . . 49

7.3 Simulated phase duration of case A. . . 50

7.4 Time Cumulative Distribution Function for case B. . . 51

7.5 Time Probability Density Function for case B. . . 51

7.6 Simulated phase duration of case B. . . 52

7.7 Time Cumulative Distribution Function for Dream Well. . . 53

7.8 Time Probability Density Function for Dream Well. . . 53

7.9 Simulated phase duration of Dream Well. . . 54

7.10 Mean total cost and duration of each case study. . . 55

7.11 Mean total cost of each P&A phase. . . 56

7.12 Mean duration of each P&A phase. . . 56

A1.1 MINV - Development of forecasted daily rental cost . . . 70

A3.1 Well Schematic for Case Studies . . . 72

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vi List of Tables

List of Tables

1.1 Chosen case studies for P&A of a platform well . . . 4

4.1 Presentation of typical P&A operations and the well intervention equipment involved in performing the operations. . . 23

6.1 Operational sequence and input to the Monte Carlo simulation model for case A. . . 43

6.2 Operational sequence and input to the Monte Carlo simulation model for case B. . . 45

6.3 Operational sequence and input to the Monte Carlo simulation model for the Dream Well. . . 47

7.1 Summary of all simulation results. . . 54

7.2 Summary of removed/reduced rig time. . . 55

A2.1 Cost input used for cost estimation in case studies. . . 71

A4.1 Detailed analysis results for case A. . . 73

A5.1 Detailed analysis results for case B. . . 74

A6.1 Detailed analysis results for Dream Well. . . 75

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List of Tables vii

Abbreviations

BOP Blowout preventer

CDF Cumulative distribution function DDU Double drilling unit

DP Drilling platform

HP High pressure

MAX Maximum

MIN Minimum

MINV Maersk Invincible

ML Most likely

NCS Norwegian Continental Shelf

N/D Nipple-down

NPT Non-productive time

N/U Nipple-up

P&A Plug and abandonment P&Aed Plugged and abandoned

PDF Probability density function PWC Perforate, wash, cement

SOI Source of inflow

WBS Well barrier schematic

WI Well intervention

WOW Waiting on weather

XMT Christmas tree

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1

1 Introduction

1.1 Motivation

On the Norwegian Continental Shelf (NCS), the first wellbores were drilled in the 1960’s and this became the beginning of what is today Norway’s largest industry (Norwegian Petroleum, 2021). The production from oil and gas reservoirs is not an infinite process, and a well’s life cycle includes planning, drilling, completion, production, and abandonment.

All wells reach the end of their life, and the authorities then require the wells to be permanently plugged and abandoned (P&Aed). The definition of plug and abandonment (P&A) implies to seal a well for production and aims to avoid contamination of the environment outside the well, migration and cross-contamination of gas and flow sources in the well, and prevent leakage to surface in and out of the well (Aarlott, 2016).

Today it is clear that the planning and facilitation for future P&A has not been a priority in the planning phase of most wells on the NCS. For instance, there is a lot of missing and valuable information about the geological formations that could have been available if the wellbores had been logged and thoroughly researched in the earliest phases of their life cycle. Without such information, the abandonment phase becomes more complex and expensive.

Another challenge is that the costs of abandonment operations can be challenging to predict and forecast. Traditionally, P&A operations are performed using drilling rigs with high daily rental costs. Rig rates are very sensitive to marked changes, and especially to changes in the oil and gas prices (Osmundsen et al., 2013). Consequently, being dependent and affected by the rig market can lead to big gaps between the planned abandonment costs and the actual abandonment costs. Considering this, P&A operations might become more flexible and predictable without such fluctuations and the need of a drilling rig.

P&A operations are very time consuming, costly and have probably been a slightly neglected focus area in the past. Despite many technological advances in the oil and gas industry in recent years, history shows that traditional P&A methods have had less technological progress. As the oil companies are committed to plug their wellbores, the Norwegian tax regime is regulated in a way that makes the state pay 78% of the P&A

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2 1.1 Motivation

expenses (Jacobsen, 2012). This means that the Norwegian state pays enormous costs every year for abandonment operations, and these costs are covered by the taxpayers in our society. Finding cost-efficient and safe methods for P&A will therefore be of great value and importance to both the industry and the society. The number of wells to be abandoned will increase in the forthcoming years as aging fields reach their economic and productive limits, and the development of more efficient technology that can cut down P&A expenses should therefore be of high priority.

According to Factpages Norwegian Petroleum Directorate (2021) in May 2021, currently a total of 7270 wellbores have been drilled on the NCS. Of these, 5315 are development wellbores, which includes injection, observation, and production wells. Approximately 507 of the development wellbores already have the status “junked” or “P&A”, which means that with today’s number approximately 4808 wellbores will be P&Aed in the future (Factpages Norwegian Petroleum Directorate, 2021). The development wellbores are divided into platform wellbores and subsea wellbores. As illustrated in figure 1.1, the amount of platform wells that require P&A in the future is greater than subsea wells, and it is therefore decided to focus on P&A approaches for development platform wells in this thesis.

Figure 1.1: Approximate number of subsea and platform wells requiring future P&A.

(Factpages Norwegian Petroleum Directorate, 2021)

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1.2 Research Question 3

1.2 Research Question

Based on the above discussion of the need for innovative and cost-efficient solutions for P&A in the industry, the following research question is formulated:

To what extent can well intervention technology reduce rig scope and perform sustainable and cost-efficient platform abandonment operations?

In order to answer this research question, three different platform well abandonment approaches, with associated cost and duration, will be explored throughout this thesis: a rig-based "case A" approach, a rigless "Dream Well" approach, as well as a combination of rig-based and rigless "case B" approach. These will be referred to as case studies, as presented in table 1.1. A new P&A method, where well intervention technology such as wireline will be taking over parts of, and the entire, traditional rig work relating to platform wells will be investigated. Further, a rigless recovery system, called WellRaizer, which is based on a hydraulic jacking principle, will be presented as for the first time in a scientific thesis. In addition to time and cost, environmental and societal factors and impact related to P&A will also form a fundamental part of the discussion.

By using the three abandonment approaches, models will be constructed and used in a Monte Carlo simulation that will produce time distribution curves for the operations. As table 1.1 shows, the P&A operations will be divided into four phases for each case study, and the Monte Carlo simulation outcome will provide details regarding cost and duration for each phase. The specific technology and operational method that is used in each phase will be presented and explained throughout this thesis. All case studies will provide a comparable relationship as the same fictitious well is P&Aed, and the simulation results will therefore be able to suggest the most appropriate approach to platform P&A.

One reason why Monte Carlo simulation is the chosen model to provide estimates for this thesis is that uncertainty and learning effects can be built into the simulation model.

The objective of the simulation is to provide a realistic time and cost potential for the various P&A approaches. To achieve as accurate estimates as possible, it is crucial to be critical and aware during data collection. Mainly data and experiences from P&A operations at Aker BP’s Valhall Drilling Platform (DP) field will be used throughout the case studies to discuss the performance of the different methods. Abandonment data from

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4 1.2 Research Question

Halliburton’s Jotun B field will also be used, as well as expert opinions and knowledge within the industry. With this data as a basis for correct estimation of the operational time and cost, this thesis will try to determine to what extent the different procedures are able to reduce future challenges, rig scope and costs of P&A operations.

Table 1.1: Chosen case studies for P&A of a platform well

Phase Case A Case B Dream well

Phase 0

Preparatory work Rig Well Intervention Well Intervention Phase 1

Reservoir abandonment Rig Rig Well Intervention

Phase 2

Intermediate abandonment Rig Rig Well Intervention

Phase 3

Conductor and wellhead removal Rig Well Intervention Well Intervention

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2 Background

2.1 Definition of Plug and Abandonment

Abandonment of a wellbore implies to isolate the reservoir and other permeable pressure zones by establishing well barriers, where cement is conventionally used for well barrier plugs. P&A of wells is important in order to prevent future leaks of hydrocarbons to the surface and to avoid damaging the environment. This operation is crucial for both the industry, society and environment, and there are high requirements for the operational execution and result. The requirements to P&A are regulated by the Petroleum Act, and simply explain that the well must be completely without any source of leakage when abandoned (Petroleum Safety Authority Norway, 2021). If there is any leakage from the well after the abandonment, then the P&A operation will not be approved by the Petroleum Safety Authority in Norway.

P&A operations require a lot of planning as several factors can affect the productivity of the operations. For instance, an operation can be suspended due to waiting on weather or waiting on equipment. Cost, time and risk estimates and safety measures should therefore always be considered in advance of an operation, as well as a thorough understanding of the wellbore.

There are several sources of inflow (SOI) in a wells overburden, that needs to be isolated.

Leakage of gas can lead to sustained casing pressure, which is a pressure that persistently rebuilds after bled-down (Sæby and Shell, 2011). In order to meet the required goals regarding P&A of wells, NORSOK standards developed by the Norwegian petroleum industry must be followed. According to NORSOK D-010 (2013), two qualified barriers must be installed to isolate the SOIs and form a well barrier envelope. The primary barrier is the first barrier against the SOIs, while the secondary barrier acts as a back-up barrier. This establish a double security in case the primary barrier fails. Further, the impermeable formations located above the reservoir and the SOIs will be referred to as seals. A well construction consists of several casing strings that are lowered into the wellbore and cemented in place. At the bottom of the casing string, a casing shoe will be present where the rounded bottom on the casing shoe facilitate running into the hole.

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6 2.1 Definition of Plug and Abandonment

Figure 2.1 illustrates a wellbore with typical casing strings and their corresponding names, which will be referred to in this thesis. The space between two casing strings where fluid can flow, is called “annulus”. A complete well is divided into several annuli where each annulus has its own unique name, such as A-annulus and B-annulus.

Figure 2.1: Example of a well construction.

We distinguish between two types of abandonment: temporary abandonment and permanent abandonment. In temporary abandonment, the well control equipment is removed and the well has been abandoned for a limited time period, but it shall be

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2.2 Platform Well Design 7

possible to re-enter the well after a planned period (NORSOK D-010, 2013). Permanent abandonment is when the well is plugged with an eternal perspective and the well will not be re-used or re-entered again (NORSOK D-010, 2013). This thesis will only consider operations and time and cost analysis for permanent plug and abandonment, and P&A is therefore referred to as permanent P&A.

2.2 Platform Well Design

The execution of P&A operations depends on the well type. When planning for abandonment of a platform well, it is crucial to review and understand the well design.

For a platform well, the wellhead, christmas tree (XMT) and well control equipment will be located at surface on the production platform (Khalifeh and Saasen, 2020).

When recovering tubing and casing strings during abandonment operations, it is important to understand the wellhead design and the interaction between all casing strings and the wellhead. Wellhead housings are associated with the following main components: starting casing head, casing hanger, casing spool, tubing head, tubing hanger and tubing spool.

Figure 2.2 illustrates some wellhead equipment associated with some casing strings.

Figure 2.2: Wellhead housings associated with the various casing strings.

(ABB Vetco Gray, 2003)

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8 2.3 Phases of P&A

The conductor is the first casing string that is put into the well. A base plate is usually attached to the casing head and placed on top of the conductor (ABB Vetco Gray, 2003).

The first wellhead component installed, the starting casing head, is installed on the surface casing, which is the first casing string that is cemented into the well (ABB Vetco Gray, 2003). Above all intermediate casing strings and the production casing, casing spools and tubing spools are installed, respectively. The function of casing spools is to hang off the next casing string, while the tubing spool is used to hang off the production tubing string.

The production tubing is not illustrated in figure 2.2, but the tubing is also supported and sealed within the tubing spool inside the wellhead. Each casing string installed on a well is suspended and seal inside of the previously installed wellhead component by means of a casing or tubing hanger (ABB Vetco Gray, 2003). The tubing head supports the tubing string and tubing hanger.

Once the tubing head has been installed in the well, the top connector provides a connector for the XMT. The XMT is installed on top of the tubing head with a tubing head adapter and provides flow control of formation fluids from the well. As discussed earlier, there should always be two well barrier envelopes in place. The XMT will be disassembled several times during an abandonment operation, which means that another well control equipment must be rigged up. Therefore, when the XMT is disassembled, well control equipment, such as a blowout preventer (BOP), is assembled on the wellhead instead. The BOP works as a large valve and can effectively close if flow control from the well is lost.

Assembly and disassembly of well control equipment is also referred to as "nipple-up"

(N/U) and "nipple-down" (N/D) well control equipment in this thesis.

2.3 Phases of P&A

The operational sequence of P&A is normally divided into three phases, “Reservoir abandonment”, “Intermediate Abandonment” and “Wellhead and Conductor Removal”

(Oil & Gas UK, 2015). The following subsections describe each phase reflecting the scope of work and the required equipment.

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2.3 Phases of P&A 9

2.3.1 Phase 0 and 1

The first phase, “Reservoir Abandonment”, aims to establish the well status and traditionally prepare for rig-based P&A. This phase also reflects preparatory work which will be referred to as phase 0 (Moeinikia et al., 2014b). Phase 0 is usually done rigless, by investigating the wellhead and rigging up a wireline unit. Chapter 4 provides further information about the wireline unit and how it operates during this phase. In phase 1, primary and secondary barriers are installed and isolates the reservoir sections of the wellbores from potential flow. The goal is to isolate the connection to the reservoir perforations through the inside of the wellbore.

Figure 2.3 illustrates a well barrier schematic (WBS) of a fictitious reservoir abandonment.

In this case, a bridge plug is installed in the bottom of the tubing. A definition of bridge plugs will be provided in section 2.4. Further, the production tubing is cut and pulled, which is conventionally performed using a rig with a BOP installed. The tubing may be left in place, partly or fully retrieved (Oil & Gas UK, 2015). Both a primary and a secondary cement plug is then installed as qualified barriers for the reservoir.

Figure 2.3: WBS with completed phase 0 and 1.

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10 2.3 Phases of P&A

2.3.2 Phase 2

Phase 2 is defined as “Intermediate Abandonment” and aims to install barriers, both primary and secondary, above all the required SOIs to isolate permeable zones in the overburden with flow potential. Conventionally, this phase is rig-based and consists of operations such as casing retrieval and barrier setting. Phase 2 completes isolation of the well by setting an open hole to surface barrier below the seabed.

Figure 2.4 is a continuation of the previous WBS, illustrating a completed intermediate abandonment where no further plugging is required in this phase. A permanent primary and secondary barrier is installed above SOI 2 to ensure cross-sectional sealing, and a surface barrier is also installed.

Figure 2.4: WBS with completed phase 2.

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2.4 Operational Procedure of P&A 11

2.3.3 Phase 3

The third and last phase is the “Wellhead and Conductor Removal”, which includes cutting and retrieval of casing strings, conductor, and wellhead. Casings and conductors are cut and removed some meters below the seabed. Conventionally, these operations are performed with a rig. When phase 3 is complete, there is no further abandonment activities, and the well is permanently P&Aed, as illustrated in figure 2.5.

Figure 2.5: WBS with completed phase 3.

2.4 Operational Procedure of P&A

There exists several methods and approaches to well abandonment as the design and composition differs from one well to another, but the goal is to establish well barriers that provides sealing both vertically and horizontally (NORSOK D-010, 2013). The P&A operational procedure is unique for every well, even though there are some general

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12 2.4 Operational Procedure of P&A

sequences that characterize most operations. The following shortly summarizes a typical P&A procedure where the main operational steps are involved:

Prepare the well for P&A:

Prior to any activity, a vessel or a rig is normally mobilized to the well location. The wellhead and the XMT are investigated to ensure optimal functionality and safety throughout the operation. A wireline unit is rigged up on platform and a wireline functionality test is performed according to safety regulations.

The wireline unit performs a drift run and a caliper run which provides diagnostics and logs that evaluates the wellbore condition and the quality of the equipment down-hole.

The log provides information about the tubing diameter and the potential amount of damage, scale and corrosion in the well.

Kill well:

Prior to the abandonment activity, the well must be killed. To kill the well, heavy kill fluid is pumped into the well. The heavy fluid ensures that the hydrostatic pressure is greater than the formation or pore pressure, and this shut off the flow into the wellbore (Halvorsen, 2016).

Cut and pull production tubing:

The tubing is cut with wireline above the production packer. Further, the annulus and tubing is displaced to kill fluid to verify optimal circulation and communication. It is necessary to cut and pull the production tubing in order to access the 9 5/8" production casing. We need fully access to the 9 5/8" casing in order to log and evaluate good or bad cement behind the casing. The information about the cement condition is essential when deciding the placement area of the cement plug barrier. According to NORSOK D-010 (2013), removal of downhole equipment is required as this can cause loss of well integrity, and control lines and cables shall not form part of the permanent well barriers.

The tubing has normally control lines attached, and this provides an additional reason why it must be removed.

Platform wells are conventionally equipped with a vertical XMT. These XMTs are secured with primary and secondary barriers and the XMT can therefore be removed before the

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2.4 Operational Procedure of P&A 13

tubing is pulled (Moeinikia, 2016). To ensure and maintain well integrity and control during the tubing retrieval, a BOP is nippled up after nipple down the XMT.

Retrieval of the production tubing is a heavy lifting operation that requires large pulling force. Normally a rig performs this operation and further operations from this stage. For instance, during the P&A campaign at Valhall DP, a jack-up rig has been utilized to retrieve the tubing (Aker BP, 2017).

Establish primary and secondary barriers

A primary and secondary barrier is installed to ensure that the reservoir is sealed both vertically and horizontally. The number of permanent well barriers that is needed to establish full cross-sectional sealing of a well depends on the number of potential sources of inflow, throughout the well. As each well is unique, the number of SOIs and seals varies.

Wells with many permeable, intermediate zones and big flow potential will therefore restore more seals than wells with fewer permeable intermediate zones.

Logging tools are run in order to determine the quality of the cement behind casings. If the logging data can verify good quality casing cement, then an internal cement plug can be installed inside the casing. If the logging data shows cement with poor quality or lack of casing cement, it is necessary to apply section milling or perforate, wash, cement (PWC) technology (Moeinikia, 2016). Figure 2.6 illustrates both a cement plug installed by using the PWC technology, as well as an internal cement plug. During this thesis’ case studies, only the PWC method and internal cement barrier method for barrier installation will be used:

– Internal cement plug: If the log can verify good quality of the annular cement bond, an internal cement plug can be verified as barrier inside the casing. A common method to install cement barriers is to circulate drilling mud and pump cement through drill pipe or coiled tubing.

– Perforate, wash, cement: PWC jobs can be used when the log shows poor quality of the annular cement bond. This involves perforating the casing, cleaning the annulus behind the casing perforations, and pumping cement downhole and out through the perforations to establish a cement plug (Knutsen, 2019).

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14 2.4 Operational Procedure of P&A

Figure 2.6: Illustration of two different approaches for barrier establishment.

It is not possible with today’s technology to log through two casing strings, and it may become necessary to cut and pull the 9 5/8" production casing in order to access and log behind the 13 3/8" intermediate casing. If this is performed and the cement is proven solid, then a plug is installed inside the 13 3/8" intermediate casing. Bridge plugs are used as foundation for upcoming primary cement barrier and reduce the chance for cement contamination, as potential flow and pressure can enter from lower areas in the well (Halvorsen, 2016).

Install surface plug:

If there is no gas and flow potential from the formations via the C or D annulus, then it is sufficient to place a surface plug inside the 13 3/8" casing. If there is sustained casing pressure from C-annulus, it becomes necessary to cut and pull the 13 3/8" intermediate casing in order to log the 20" casing cement, and then establish a full cross-sectional cement barrier inside the 20" surface casing. If there is sustained casing pressure from the D-annulus, it might become necessary to cut and pull the 20" surface casing, in order to establish a full cross-sectional cement barrier inside the 30" conductor casing. The surface cement plug is the final well barrier.

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2.5 P&A Cutting Techniques 15

Cut and retrieve conductor, casing strings and wellhead:

The final step of the P&A procedure is to cut and remove the conductor and casing strings, including the wellhead, a few meters below the seabed.

2.5 P&A Cutting Techniques

Cut and pull casing operations are necessary in situations where the annular barrier is poor or non-existent and where the casing strings overlap, as explained in the typical P&A procedure in section 2.4. Pipe retrieval requires large amounts of pulling force, and there exists several cut and pull tools and methodologies that can cut through multiple casing strings and solve challenges associated with this.

As mentioned earlier, it is common to cut production tubing with wireline. Other cutting operations can be performed using explosives, chemicals, mechanical cutters or abrasive cutters (Khalifeh and Saasen, 2020). Mechanical cutting or abrasive cutting is the preferred method for casing cutting (Moeinikia, 2016). Mechanical cutters are power-driven, while abrasive cutters are based on a sand cutting technique or a water jet cutting technique. For sand cutting, a high volume of abrasive particles are injected into a water jet and pumped at low pressure, while for water jet cutting, a low volume of abrasive particles are pumped at high pressure (Khalifeh and Saasen, 2020). To enhance the cutting performance, casing strings are conventionally under tension during the cutting operation.

In today’s marked, there are several cutting tools with different functions, specifications, and benefits. Different equipment can perform cutting operations with significant differences in speed, and an example of this will be presented in the case study in section 6.2.

2.6 Literature Review

Currently, there is only a limited amount of information within the field of rigless P&A of platform wells, as most of the literature considers usage of intervention vessels for P&A operations of subsea wells. Searching for "rigless P&A" on Google Scholar only provides 58 search results. Therefore, this section will particularly present a brief overview of literature that is relevant for rigless P&A and have a focus on duration and cost estimation.

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16 2.6 Literature Review

Wittberg (2017)’s research stands out by investigating P&A of platform wells, where an alternative approach to rigless P&A using well intervention equipment is presented.

He concluded that combining intervention equipment such as wireline and coiled tubing with high energy P&A technology could be utilized for reservoir abandonment, while complex operations in a wells overburden should be plugged using a drilling rig. He further recommended to provide a time and cost analysis where the rigless approach is compared to a conventional P&A approach.

Mikalsen (2012) suggested an approach using a hydraulic pulling and jacking unit together with coiled tubing, instead of using a rig for platform P&A. Time and cost related to the P&A approach was provided and based on historical data, but without explicitly presenting the model used for the estimation. His results showed that the rigless method was less time-consuming, but had a much higher day-rate, than the conventional method.

Nevertheless, he concluded that reduced operational time and personal would lead to a major overall cost saving that eventually would make the P&A campaign more cost-efficient using the rigless method.

Raksagati (2012) used Monte Carlo simulations to forecast cost and duration of several P&A approaches of subsea wells, both for single well P&A and for multi-well "batch"

P&A. The major differences between his approaches was the application of rig or vessel technology, as well as a combination of rig and vessel technology. However, the results provided an insignificant difference in cost and duration between the rigless or rig-based method. Based on the findings, he nevertheless suggested a vessel-based approach for P&A in order to free rigs to perform drilling operations instead. In addition, he suggested to increase the number of wells in batch operations in order to reduce the cost of P&A per well. There are, to this thesis knowledge, little research and estimates of time and cost for rigless platform P&A. Therefore, to make the contribution of this thesis even more relevant, it could be interesting to perform a similar research approach for platform wells.

The importance of collecting reliable and a sufficient amount of data for accurate simulation and analysis is significant within the oil and gas industry. Moeinikia et al. (2014a) also used a Monte Carlo simulation approach to evaluate cost efficiency of rigless P&A for a subsea multi-well campaign. They used, for the first time, an approach that included learning curves, correlations, and possible risk events to evaluate time and cost of a subsea

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2.6 Literature Review 17

batch P&A. Findings from their studies showed that these factors had a significantly positive impact on cost and duration of the multi-well campaign. This makes it especially interesting to include expert opinions involving learning curves and risk for time and cost estimation within platform P&A in this thesis.

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3 Understanding P&A Costs and Impact

3.1 Cost-Influencing Factors

Traditionally, P&A operations are performed using drilling rigs with high daily rates. The rig rates contribute to 40-50 percentage of the total costs of P&A, and thus affect the profitability of abandonment operations (Straume, 2016). Due to both unforeseen and foreseen changes in the oil and gas industry and the rig market, it is a challenge to predict future daily rig rates. For instance, as a response to Covid-19, the Norwegian parliament introduced several measures to secure the financial challenges, and the new tax regime provided incentives to stimulate the production drilling activity (Government.no, 2020).

However, weak oil prices and an increased focus on renewable energy are causing cutbacks in exploration drilling activity. When estimating the costs of rig-based abandonment operations, it is crucial to understand the relationship between the rig rates and their influencing drivers, as this can improve budgeting and cost analysis.

The rig rates are sensitive to the oil and gas price in the market, and a change in supply and demand for oil and gas will lead to a shift in the oil and gas price, as shown in figure 3.1. In short terms, increased oil and gas price will not lead to any big change in consumer consumption as today’s society is still very dependent on this form of energy supply. The demand for oil and gas is therefore inelastic as shown in figure 3.1a (Hannesson, 1998).

This can also be confirmed in Osmundsen et al. (2013)’s study, where their econometric analysis implicated that the current oil and gas price has a weight of 6.9%, while the expected future price, which is assumed to influence the rig market, has a weight of 93.1%.

In long terms it is possible to find substitutes to oil and gas which means that a change in the oil and gas price can lead to a bigger negative shift in the demanded oil quantity.

Considering this, the rig rates will probably decrease as a consequence. Meanwhile, increased prices for oil and gas can provide opportunities for new investments that will increase the supplied oil quantity. For instance, investing in new and efficient technology, higher storage and production capacities, and new oil fields can increase the volume of oil and gas. In long terms, both the demand and the supply for oil and gas can therefore be elastic, illustrated in figure 3.1b and 3.1c (Hannesson, 1998). Osmundsen et al. (2013) also

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3.2 Time-Cost Relationship 19

provided an analysis for the long run price elasticity, indicating that a 10% permanent increase in the oil and gas price index would increase the rig rates by 12.3%.

(a)Inelastic demand (b) Elastic demand (c) Elastic supply Figure 3.1: Graphs showing price elasticity of supply and demand for oil and gas.

Obviously, increased exploration and production in the oil and gas industry, as well as high expected oil and gas prices, will stimulate the rig market and increase the rig demand.

Without the need of a rig for P&A operations, one can exclude a lot of uncertain factors related to rig rates and the rig market in the cost estimations. This thoroughly emphasize that it is easier to plan the costs for well abandonment if the operations are performed rigless, and that one probably can reduce the costs significantly by not using a rig.

3.2 Time-Cost Relationship

There is always a relationship between time and cost in a project, and several measures have been performed on the NCS regarding the time-cost relationship for P&A. A common opinion is that working in a time-efficient manner will reduce the total cost of a project.

Thorough planning of each operation, to anticipate uncertain events that can increase non-productive time, as well as having a contingency plan in case of bad weather, are just a few examples of many factors that can affect the project efficiency.

For instance, Aker BP has performed platform abandonment operations at Valhall DP in three large P&A campaigns, also known as batch operated P&A. This batch P&A campaign involved the abandonment of 30 well slots on the platform, by using a jack-up rig that could skid between the several well slots. The main advantage of batch P&A is to gain learning outcome, and the risk for uncertainties and surprises can be reduced for

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20 3.3 Environmental Impact

each subsequent plugged well slot. This method can largely lead to more effective P&A operations and a reduction in the time spent per well. The graph in figure 3.2 confirm that there has been a steady improvement progress throughout the batch campaign regarding the operational duration per well at Valhall DP. The estimated time and cost of the P&A campaigns at Valhall DP was originally 10 years and NOK 15.5 billion, but instead the work was complete in 4 years at a total cost of NOK 10.1 billion (Aker BP, 2021c).

This further supports the statement "time is money". A constant focus on continuous improvement for P&A operations may therefore often lead to shorter operational duration and reduced costs.

Figure 3.2: Improvement progress and performance of batch P&Aed wells at Valhall

DP. (Aker BP, 2021b)

3.3 Environmental Impact

An integral part of the Norwegian petroleum policy is to take care of the environment and climate. A large part of emissions to air comes from the use of gas turbines that generate electricity (Gavenas et al., 2015). A central source of emissions are the combustion of natural gas and diesel in turbines to produce electricity offshore.

Rig activity is normally very energy-consuming and driven by natural gas and diesel generators, and contributes to emissions such as carbon dioxide (CO2) and nitrogen oxides (NOx). A study done by the Norwegian Petroleum Directorate (2019) explains that

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3.3 Environmental Impact 21

approximately 14 million tonnes of CO2 were emitted from the NCS in 2019, and 84.6%

of released CO2 was derived from gas turbines.

There is also a large difference in the amount of emissions coming from the different drilling rigs. For instance, the Maersk Invincible (MINV) jack-up rig has plugged 14 wells on the Valhall DP field. As probably for the first time ever, this drilling rig was powered fully from shore and reduced the annual local emissions by 15200 tonnes of CO2 and 168 tonnes NOx (Aker BP, 2018). This thoroughly emphasize a great demand and need for efficient technology that can reduce the environmental footprint, as it is proven to reduce environmental damage.

When using large drilling rigs for P&A operations, potential emissions must be considered, estimated, and calculated. If abandonment activities can be performed without costly and energy-consuming drilling rigs, this can entail significantly lower emissions (Forskningsrådet, 2018). On platforms, this means that the carbon footprint might be remarkably reduced if well abandonment operations can be carried out by using electrically powered well intervention equipment instead of drilling rigs.

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22

4 Well Intervention Technology

Most of the operations described in the typical P&A procedure in section 2.4 are conventionally performed using a rig. In order to take a step towards a rigless P&A procedure, alternative abandonment methods and opportunities by using well intervention equipment will be investigated throughout this chapter.

Well intervention can be described as safely entering a well with well control for the purpose of doing several operations other than drilling (Kratz, 2012). During a well’s life cycle from initial production to abandonment, intervention work includes operations related to maintenance, repairing and replacement. Well intervention operations were historically performed with drilling rigs, but with today’s technology it is possible to re-entry wells with substitutes to the drilling well control systems and rigs for delivery of non-drilling services (Kratz, 2012). Well intervention equipment is normally diesel powered, but can also be fully electrically driven.

Table 4.1 briefly introduce the well intervention technology that will be deployed in this thesis case studies and time and cost analysis. The table illustrate typical P&A operations and the corresponding intervention technology that can be used instead of a rig. This chapter will mainly present a hydraulic jack and a wireline unit. The wireline intervention equipment, presented in section 4.1.1, has been described several times in the past, and this thesis therefore refer interested readers to the reference literature for a more detailed explanation. A hydraulic jack called WellRaizer is presented in section 4.2.

This technology has never been presented in a scientific thesis before and will therefore be emphasized and thoroughly described in this section. A comprehensive explanation of how this technology can perform complex P&A operations will be provided.

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4.1 Conventional Technology 23

Table 4.1: Presentation of typical P&A operations and the well intervention equipment involved in performing the operations.

4.1 Conventional Technology

4.1.1 Wireline

The purpose of a wireline unit is to perform well intervention activities and to check the wellbore conditions by lowering equipment down into the well. Examples of equipment that can be attached to the wireline is running tools, logging tools, pulling tools, cutters, and many more. Wireline technology are used for a wide variety of purposes such as logging, removal of scale, fishing operations, casing perforation and retrieval, tubing cutting, and installation of plugs. The preparations for abandonment, the “preparatory phase”, normally starts with wireline diagnostics. Wireline investigation and logging can confirm that a wellbore is deformed or collapsed and indicate that a work string is unable to reach the reservoir or the required depths for placement of the final P&A barriers (Aker BP, 2017).

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24 4.1 Conventional Technology

Wireline equipment can be divided into two different cable systems: slick line and braided line. The slickline is a smaller, non-electrical cable, while the braided line can provide electricity and has a higher tensile strength (Steen, 2013). Naturally, the braided line is thus more frequently used during heavier operations. For simplicity, wireline will refer to both slick line and braided line throughout this thesis.

Compared to other well intervention equipment, a wireline unit is rather small and easy to rig up. During wireline operations, pressure control devices are used in order to maintain well control and to prevent leakages and well blowouts. As illustrated in figure 4.1, the pressure control equipment is installed on top of the XMT, and mainly consists of a pressure control head that controls grease injection, lubricators that provides sealing and fluid control, a stuffing box and a BOP. The stuffing box forms the primary barrier and consist of rubber elements that ensures sealing around the wireline (Mikalsen, 2012). The BOP forms the secondary barrier, where a shear ram closing element closes across the wireline when the BOP is closed to provide wellbore sealing. With this setup, it is possible to maintain well control, as well as the two-barrier philosophy while lubricating in and running tool strings down live pressurized wells (Wittberg, 2017).

Figure 4.1: Illustration of wireline rig up.

(Parveen Industries Pvt. Ltd., nd)

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4.2 Emerging Technologies 25

It is possible to rig up a wireline unit almost anywhere, as it has a high flexibility. If wireline is used on a drilling rig, it is normally run through the rotary table of the drillfloor.

For rigless operations, it is possible to run the wireline unit through a wireline mast or through a P&A working unit. For a P&A unit, it may not be necessary with all the available systems that can be found at the drilling rig (Khalifeh and Saasen, 2020). Section 4.2 will explain a hydraulic jacking system which in many ways serves as a drilling rig, where the wireline equipment can be run through the system.

4.2 Emerging Technologies

To pull tubing, casing, and conductor from a well can be extremely difficult to perform without a rig. As big surface forces are needed in such pulling operations, this has been an obstacle to a fully rigless P&A operation, and the "easiest" method has then been to use a drilling rig that ensure sufficient pulling force. In the following subsections, some emerging technologies will be thoroughly described, involving a hydraulic jack/recovery system called WellRaizer, that can retrieve tubing, casing, conductor, and wellhead without a rig.

The recovery system can remind of existing modular rig units or P&A units, which is also an alternative to expensive drilling rigs. For instance, the abandonment project Jotun B, executed by Halliburton AS, utilized a cost-efficient modular P&A unit (Helgesen, 2018).

Nevertheless, WellRaizer is revolutionary when it comes to abandoning platform wells, as it takes over heavy cut and pull operations that is usually rig dependent scope. The system is designed to provide and facilitate all P&A operations, and can perform pulling operations involved in all phases of the P&A sequence (Claxton Engineering, 2020a).

This covers retrieval of production tubing and casing strings in phase 1 and phase 2 respectively, and conductor and wellhead removal in phase 3. Wireline can be run through the WellRaizer unit, and the recovery unit is also compliant with running cement through drill pipe for barrier installation.

4.2.1 WellRaizer

WellRaizer, the heavy duty rigless well recovery system owned by Claxton Engineering Services Ltd, is a hydraulic jacking system that provides the recovery offshore of oil and gas conductor pipes and casings of up to 36” in diameter (Claxton Engineering, 2017).

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26 4.2 Emerging Technologies

This technology has been utilized on the NCS to support rigless recovery of abandoned wells, and by using WellRaizer, a jack-up rig or a platform-based drilling derrick is no longer necessary (Claxton Engineering, 2017).

WellRaizer is compliant with NORSOK Z-015 and fulfill the design codes and safety standards for work on the NCS (Claxton Engineering, 2020d). The system is equipped with a safe working load of 300 metric tons and is designed in lightweight modular units minimizing rig-up time and complexity, with no component weighing over 10 metric tons (Claxton Engineering, 2020c). It is a flexible unit that is capable of skidding in both the X and Y axes, which makes it possible to skid between several well slots on platforms. This is especially advantageous in the execution of batch P&A campaigns. The design philosophy of the unit is to be compact and efficient during rig up and operation (Claxton Engineering, 2020a). The compactness is beneficial as the unit becomes more robust against weather, leading to reduced dependency on weather during operations. In addition, the hydraulic jack is smaller and more sustainable compared to a rig and can thus contribute to a reduced carbon footprint. For instance, the WellRaizer is driven by diesel generators, but emits only 20% as much emissions compared to a rig (M. Straume, personal communication, 2021).

The WellRaizer, illustrated in figure 4.2 mainly consists of the following equipment:

• A lower and upper cassette and a lower and upper pneumatic spider - the pneumatic spiders are designed with slips and utilized to grip the landing string.

• Landing string - provides a main role in the in-riser system and interface with the wellhead, ensuring safety during the jacking operation.

• Four hydraulic jacking cylinders - generates high lifting force and exert linear strength that produce the lifting or pulling action.

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(a) Illustration of the WellRaizer unit.

(b) Placement of the lower pneumatic spider, on top of the lower cassette.

(c) Placement of the upper cassette. (d) Placement of the upper pneumatic spider.

Figure 4.2: Illustration of WellRaizer rig up.

(Claxton Engineering, 2020a)

In addition, the recovery system consists of service tools such as a double drilling unit (DDU), a multi-string cut bandsaw severance, and a make-and-break system. The following provides a brief introduction to these tools as they form a central part of the conductor recovery system and procedure:

Double Drilling Unit:

When recovering multi-string casings, a drill and pin operation will be executed to ensure a safe simultaneous retrieval. This operation will be performed by a DDU unit mounted on the jacking frame on the hydraulic jack. After drilling the multiple casing strings, it is important to install a pin in the multi-string casing to mitigate the dropped object potential when handling the pipes on deck. Figure 4.3 illustrates a drilled and pinned multi-string casing.

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Figure 4.3: Drilled and pinned multi-string casing.

(Aker BP, 2021a)

Bandsaw severance:

The bandsaw can cut through steel conductors and casing with fully cemented and grouted annuli. The bandsaw is lifted and installed around the tubular using an open front and gate clamp system which is manually locked and clamped onto to the tubular. This operation commences once the combined strings have been drilled and pinned. Once the cut is complete, a "debris cap" is installed to the bottom of the cut joint prior to laying out to the pipe deck to ensure that no debris or dropped object hazards are encountered during the lay out operation (Claxton Engineering, 2020b). Figure 4.4 illustrates a bandsaw operation where the bandsaw cut between two installed casing pins.

Figure 4.4: Bandsaw cutting operation.

(Claxton Engineering, 2020a)

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Make-and-break system for drill pipe:

A lightweight make-and-break system must be in place and skid in on the WellRaizer jacking frame before drill pipe joints are put in service. The purpose of this system is to ensure that all pipe connections are screwed together and tightened with torque.

4.2.1.1 Conductor and Wellhead Removal

Earlier, the conventional method to install the conductor casing was by conductor driving.

This means that the conductor is hammered into the ground and cemented in place. At Valhall DP, the conductors are driven using the hammer technique to drive the pipe into the top-hole formations above SOI 1 (Aker BP, 2017). By using this installation method, the conductor can be considered as an independent part of the wellhead system, and will therefore be handled accordingly during the WellRaizer conductor removal in this thesis.

As explained in section 2.2, the wellhead is placed on top of the conductor. In order to retrieve the conductor, a pulling connection must be established between the conductor and the wellhead. To achieve this, a "drill and pin" operation must be performed below the wellhead to connect the conductor to the surface casing. Without pinning the conductor, the surface casing will be pulled instead during the WellRaizer conductor removal operation.

The cement around the conductor creates friction between the conductor and the surface casing when the pin is installed, and this further contributes the conductor to be pulled upwards.

Prior to the start of the conductor and wellhead pulling operations, all SOIs must be isolated and the barrier envelope tested. An environmental plug must also be installed and tested for leakage. The first step in the drill and pin operation is to attach the drilling unit to the conductor. The purpose of the drilling unit is to drill through the conductor and surface casing until the drilling head penetrates the opposite side. A pulling pin is then inserted to the conductor before cleaning the area with vacuum pump. When the pinning work is complete, the conductor and wellhead removal can start as per Claxton’s WellRaizer instructions.

The following procedure is provided by Claxton Engineering and guides us through the conductor and wellhead removal procedure using WellRaizer (C. Wetton, personal communication, 2021):

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1. The pneumatic spiders are split, and the 30" landing string is run through the recovery tower to interface with the wellhead, as illustrated in figure 4.5 and figure 4.6.

The landing string is designed with a pre-drilled hole, which will be of importance in step 3. Further, the upper spider is engaged onto the landing string and the overshot to the wellhead is fully engaged, as shown in figure 4.7.

Figure 4.5: Splitted pneumatic spiders and

prepared for the landing string.

(Claxton Engineering, 2020c)

Figure 4.6:

Landing string running through the recovery

tower.

Figure 4.7:

Landing string interface with the

wellhead.

2. A drift run is performed to identify the wellbore condition and to determine the cutting depth, before starting the conductor cutting operations. When the conductor cutting is complete, a 4" load pin is attached to the 30" landing string in the pre- drilled holes. The platform main crane will be attached to the landing string to support any lateral movement, and therefore the load pin equipment is necessary.

3. The lower slips at the lower pneumatic spiders are released, and power is raised up the jacking cylinder to the required elevation. Further, the lower slips are engaged, and the conductor is set into slips, before releasing the upper slips. Then the jacking system is retracted. Figure 4.8 illustrates the concept of the WellRaizer jacking cylinders.

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Figure 4.8: Elevation principle of the jacking cylinders.

4. Both pneumatic spiders must be engaged in preparation for surface pinning and severance operations. The DDU is positioned around the casing 1.5 meters below the wellhead and the multi-string casing is then drilled, as shown in figure 4.9. Once drilled, a 4" load pin is installed. Further, the DDU is re-positioned 0.75 meters above the previously drilled holes, before drilling through the dual strings. These holes are for the "sacrificial pin" that is used with debris caps in a later stage. The debris cap aims to protect the pipe. The bandsaw unit is then positioned around the casing and cut between the already installed pins, as illustrated in figure 4.10 and 4.11. When the casing is cut, a debris cap is installed to the first wellhead section in order to reduce the risk of dropped objects. The first cut casing section is then transferred away from the well center.

Figure 4.9:

DDU operation.

Figure 4.10:

Bandsaw operation.

Figure 4.11: Cut casing and drilled 4" hole.

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5. The sequence of the upper and lower slips operation to raise the conductor to the next required cut elevation is then repeated. The DDU is again positioned around the 30" conductor casing, this time 0.75 meters below the first casing coupling.

Once drilled, a 4" load pin is installed. The DDU is then re-positioned 0.75 meters above the first casing coupling and drills through the dual strings, before installing a sacrificial pin for use with the debris cap. The bandsaw unit is then positioned around the casing and can start cut between the already installed pins. Once the cut is complete, the cut casing section can be removed. This procedure is repeated until the entire casing unit is retrieved.

4.2.1.2 Tubing Recovery

The production tubing is cut and pulled during the first phase of a P&A operation. This operation also requires high surface pulling forces in order to pull the entire tubing unit, and has therefore been a challenge regarding rigless abandonment methods. Using the WellRaizer recovery system is therefore suggested as a new method to pull out the tubing.

Unlike the conductor and wellhead removal, there is no barrier envelope in place prior to this operation. The pulling structure is therefore slightly different as a BOP must be installed together with the WellRaizer unit in order to ensure well control during the tubing recovery.

Tubing recovery requires a low-weight jacking system and a platform crane, meanwhile the WellRaizer will provide a stable structure of the system. This low-weight equipment is easy to transport and install on platforms. During tubing recovery, the XMT will be removed and a high pressure (HP) riser will be run on top of the wellhead. Further, a BOP will be installed on top of the HP riser system. The HP riser acts as a conduit between the wellhead and the BOP and provides structural and global integrity (Oil States, 2019). In that way, well control is maintained during tubing recovery operations.

Figure 4.12 illustrates the design of this suggested tubing recovery system.

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Figure 4.12: Suggested tubing recovery rig up.

As mentioned in section 2.2, the top of the production tubing is attached to the tubing spool on the wellhead. Drill pipe connections are properly broken in as per the make- and-break system through the WellRaizer recovery tower. A hanger retrieval tool will be run on drill pipe through the recovery system and attach to the tubing spool in the wellhead. This ensures an interaction between the cut tubing and the drill pipe. With

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such a recovery system in place, the jacking system and the platform crane can commence the pulling activity. As for the conductor and wellhead recovery, the tubing recovery is based on the same principles where the tubing is pulled and cut in several sections. It is not necessary to perform drill, pin and cut operations with DDU and bandsaw during tubing recovery as the tubing is a low-weight, single string. When the tubing is jacked up with the jacking system to the selected length, the make-and-break system then breaks the tubing in its connections.

4.2.1.3 Casing Recovery

Phase 2 of the abandonment procedure normally involves pulling operations of casings.

Therefore, a method for casing recovery performed with the WellRaizer is suggested.

Casing recovery requires bigger pulling forces than tubing recovery, as the casing strings have higher weight and are cemented in place. As for the tubing recovery, a BOP will be in installed together with the WellRaizer unit also during casing recovery.

The XMT will be removed and a HP riser will be run on top of the wellhead. Further, a BOP will be installed on top of the HP riser system. A recovery string, illustrated in figure 4.13, will then be run with a casing spear attached. This allows to run the recovery string to the area where the casing spool is placed to engage the recovery string to the casing. The tubing spool must be removed in order to access the casing spool, but this issue is already solved during tubing recovery. The casing spear ensures an interaction between the casing and the recovery string and makes it possible to pull the casing.

The WellRaizer casing recovery is based on the same procedure as presented in section 4.2.1.1. When the casing string is jacked up with the hydraulic jacking system to the selected length, it is broken in its connections. A 9 5/8" casing may just require a simple casing tong for the break-operation, while a 13 3/8" casing may require usage of the bandsaw unit as it is more massive.

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4.3 Limitations 35

Figure 4.13: Suggested casing recovery rig up.

4.3 Limitations

It will not constitute a large part of this thesis, but it is however worth to mention some issues related to the rigless approach. Rigless P&A requires the same surface equipment that is positioned at drilling rigs. Platforms on the NCS have varied size and deck space, and the smallest platforms might face some issues related to the deck space on board for

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36 4.3 Limitations

surface equipment. Limited deck space can therefore be an obstacle for rigless P&A as big infrastructure packages must be transported and placed on board the platform, containing for instance a hydraulic jacking unit, wireline, cementing systems, mud systems, pumping services and many more. To solve issues related to limited deck space, equipment must be rigged down and removed in order to obtain deck space, before new equipment can be rigged up. When using well intervention equipment on platforms, accommodation of P&A crew must be considered as well. Some platforms are unmanned, which means that the P&A crew must be transported to and from the platform installations. It is therefore crucial to consider and investigate the deck space and crew capacity when planning for rigless P&A operations on platforms. Limited deck space and unmanned platforms that require crew transfers will probably lead to a less effective operation.

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37

5 Estimation Method and Data Collection

For the purpose of this thesis, Aker BP has provided with internal data for P&A operations.

To understand the scope of rig-based and rigless P&A regarding time and cost, a simulation model is built based on this data. This chapter briefly present the simulation methodology used to estimate the abandonment duration and cost for this thesis’ three case studies.

The modeling procedure will be explained, as well as the chosen uncertainties that will be included. Further, data collection reflecting parameters like cost and duration are given in section 5.2.

5.1 Methodology

In order to carry out time and cost estimations for the P&A operations, the probabilistic application iQx P1, produced by AGR Software, is used. P1 is a probabilistic simulation tool used to estimate operational time and cost where potential risks are considered and included. This tool applies Monte Carlo simulations where each time and cost output is the result of thousands of simulations. P1 runs 10000 iterations by default and provides an unbiased representative group of samples based on a large group of possibilities. By using this simulation method, it is possible to predict the chances of achieving objectives within any given time or cost output.

5.1.1 Monte Carlo Simulation

The Monte Carlo simulation technique is a numerical model that obtains statistics of output variables, given the statistics of the input variables (Al-aboodi, 2014). The input data might be defined as random or uncertain values. In each trial, the input values are sampled based on their distributions, while the output variables are calculated using the computational model (Cruse, 1997). The output is given as a range of numbers with associated probabilities of occurrence for all the possible outcomes within that range.

The simulation model must be defined when applying P1 for Monte Carlo simulation. In this thesis’ case studies, the duration will be forecasted and presented as output of the model. Further, proper data must be gathered and used as model inputs. Data gathering is the most time-consuming process of the simulation method, and should be thoroughly

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38 5.1 Methodology

executed to provide the most accurate outcome possible.

The probability distribution shape that is used for the input data is the PERT distribution, which is based on the following input parameters: minimum (MIN), maximum (MAX) and most likely (ML) values. The distribution provides a smooth curve where the "ML"

estimate is favored over the MIN and MAX estimate. By this, it is trusted that even if the ML value is not exactly accurate, there is an expectation that the resulting value will be close to that estimate (Structured Data LLC, nd). The simulation tool then generates the input by taking random sample according to the defined PERT distribution.

The output of the Monte Carlo simulation will be given as histograms and distribution curves, presented as a cumulative distribution function (CDF) and a probability density function (PDF) where percentiles will be obtained. Figure 5.1 provides an example of these two distributions. The X-axis in both functions will be representing the possible output values. The Y-axis in the PDF curve presents the occurrence probability corresponding to the value on the X-axis, while the Y-axis in the CDF curve presents the probability that the outcome takes a value that is equal or less than the corresponding value on the X-axis (Moeinikia et al., 2015).

Figure 5.1: Example of a CDF and PDF distribution curve.

(Moeinikia et al., 2014b)